Hydrocarbons such as oil, natural gas, etc., may be obtained from a subterranean geologic formation, e.g., a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbons to reach the surface. In order for oil to be produced, that is, travel from the formation to the well bore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the well bore. Unobstructed flow through the formation rock (e.g., sandstone, carbonates) is possible when rock pores of sufficient size and number are present for the oil to move through the formation.
However, many wells cannot produce at economic rates without some sort of stimulation treatment. A common method is to subject the formation to hydraulic fracturing. Fracturing of a subterranean formation is accomplished by pumping a fracturing fluid into the wellbore at a sufficient pressure (above formation parting pressure) and flow rate such that cracks are opened into the surrounding formation. The fracturing fluid typically contains a proppant which functions to prop open created fractures such that hydrocarbons may flow. Productive capability of the well is therefore increased.
The development of suitable fracturing fluids to convey the necessary hydraulic force when forced downhole using hydraulic pumps is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and high shear rates which may cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous based liquids which have been either gelled or foamed. When the fluids are gelled, typically a polymeric gelling agent, such as a solvatable polysaccharide is used, which may or may not be crosslinked. The thickened or gelled fluid helps keep the proppants within the fluid during the fracturing operation. Aqueous fluids gelled with polymers have also been widely used as gravel-packing, frac-packing because they exhibit excellent rheological properties.
Such hydraulic fracturing fluids may be “broken” or have their viscosities reduced by a separately-added conventional gel breaker such as an oxidizer and/or an enzyme. However, if the breaker is added “externally”, that is separately from the hydraulic fracturing fluid, there is often difficulty fully contacting all of the fracturing fluid with the gel breaker since the gel breaker must penetrate and contact the fracturing fluid within all of the fractures. This full contact is rendered more difficult by the fact that the fracturing fluid has, by design, increased viscosity, which may tend to inhibit mixing.
An approach that may work is to use an “internal” breaker that may be pumped and introduced with the fracturing fluid, but which has a delayed break profile until after the hydraulic fracturing is complete. Some current oxidative breakers are solids or encapsulated solids which have delayed breaking profiles because it takes time for the solids to dissolve or time for the encapsulant or shell to dissolve or otherwise disintegrate and release the breaker.
Rheology testing shows that the current oxidative breakers do not work effectively at temperatures from about 180-250° F. (82-121° C.) because even after being broken with these breakers, the fluid “reheals” or gains viscosity when cooled to ambient temperature, even though the fluids show a viscosity decrease in a fracturing fluid at bottom hole temperatures. Increasing the loading of the breaker decreases the initial viscosity of the fracturing fluid and yet may still show rehealing at room temperature.
It would be desirable if alternative internal breaker compositions and methods could be devised for aqueous fluids gelled with polymers to give fluid designers more flexibility when designing the composition and use of polymer-gelled aqueous fluids.